Bitumen recovery from oil sands is a challenging activity that requires accessing subterranean bitumen, extracting the bitumen from the subterranean sand and then recovering the bitumen from the subterranean location to above ground. There are numerous proposed methods for recovering bitumen from oil sands. The Background section of US Patent Application No. 2008/0139418 provides a review of many recovery methods including strip mining, cold flow technique, cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD) and vapor extraction process (VAPEX).
Strip mining removes bitumen together with sand from underground and then extracts bitumen from the sand while above the ground. Strip mining is not an in situ extraction method because it involves extracting bitumen from sand after removing the sand from the ground. In situ extraction of bitumen involves extracting bitumen from sand in its natural location underground. In situ extraction is more desirable than strip mining because it is less damaging to the landscape than strip mining.
The cold flow technique is only useful for recovering oils that have low enough viscosity to pump at reservoir conditions. Bitumen is too viscous in most subterranean oil sand deposits to allow the cold flow technique to be a reasonable method for recovering bitumen from oil sands.
VAPEX is a method that requires injecting hydrocarbon solvents into a first horizontal well that extends into subterranean oil sands. The solvents penetrate into the oil sands, reduce the viscosity of bitumen by dilution and enable the bitumen/solvent mixture to drain into a second horizontal well below the first from which recovery of the bitumen/solvent mixture occurs. Desirably, hydrocarbon solvent is removed from the bitumen above ground and desirably recycled. The VAPEX method is a “cold” process, which means the material injected into the well is not heated any appreciable amount as opposed to “hot” processes (commonly known as, thermal methods) such as CSS and SAGD where steam is injected into a well. Cold processes such as the VAPEX method are less efficient at extracting bitumen than hot processes such as CSS and SAGD processes because bitumen viscosity is higher at lower temperatures. Therefore, to be effective, the VAPEX method requires injection of large amounts of hydrocarbon solvents into the well in order to sufficiently dilute the bitumen to achieve drainage.
Use of hydrocarbon solvents, particularly high concentrations of hydrocarbon solvents, can be undesirable in in situ bitumen recovery processes. Hydrocarbons can cause asphaltenes to precipitate from bitumen and the precipitated asphaltenes can undesirably reduce the reservoir permeability. Additionally, hydrocarbon solvent can be lost into the surrounding subterranean environment, which can result in environmental contamination concerns and increased processing costs. Use of large amounts of hydrocarbon solvents, necessary for suitable solvating of bitumen, also requires and extra process step to recover the hydrocarbon from the bitumen upon extraction of the bitumen. Therefore, it is desirable to avoid both “cold” process methods and the use of hydrocarbons during in-situ bitumen recovery.
CSS and SAGD processes are “hot” processes (that is, thermal methods) that use hot steam to decrease the viscosity of subterranean bitumen. In these processes steam is injected down a first well into subterranean oil sands. The steam penetrates the sands and lowers the viscosity of bitumen by heating the oil sands, which facilitates flow of the bitumen through the sands into either the first well (CSS) or to a second well (SAGD) from which recovery of the bitumen occurs. With the CSS method, steam is injected into a well at temperatures of 250° C.-400° C. The well then sits for days or weeks during which time the steam heats bitumen in the subterranean environment around the well causing bitumen to drain into the well and after which hot oil mixed with condensed steam is pumped out from the well for weeks or months. Then the process is repeated. In the SAGD process two horizontal wells are drilled, one below the other (generally approximately five meters apart). Steam is injected into the upper well, heating bitumen in the surrounding subterranean environment thereby lowering the viscosity of the bitumen causing it to flow into the lower well. The resulting bitumen and condensed steam mixture is subsequently pumped to the surface from the bottom well. According to US Patent Application No. 2008/0139418, recovery of bitumen from an oil sands reservoir by CSS is typically only about 20-25 percent (%) while recovery in SAGD processes is reportedly up to about 60% of the available bitumen in the oil sands reservoir.
Typically, steam alone (without additives) is used for oil recovery in SAGD. The latent heat of condensation at the steam chamber edges lowers the viscosity of the bitumen sufficiently to allow gravity drainage. This process is however, slow and steam to oil ratios (SOR) of about 3:1 are typically needed. It is thought that an additive that enhances the formation of oil-in-water emulsions would enhance the rate of drainage through the porous chamber (due to smaller emulsion droplets) and perhaps allow less water usage by decreasing the SOR.
A modified version of the SAGD process is also known. U.S. Pat. No. 6,230,814 describes what has become known as the expanding solvent steam assisted gravity drainage (ES-SAGD) process. The ES-SAGD process requires combining hydrocarbons with steam in a SAGD-type process so the hydrocarbons can solubilize bitumen in subterranean oil sands to further reduce bitumen viscosity to facilitate the drainage of bitumen into a second well hole for recovery to above ground. The reference identifies suitable additives as hydrocarbons having from one to 25 carbons. However, as explained above, it is desirable to avoid injecting hydrocarbons into a well in order to facilitate removal of bitumen.
Conventional alkaline enhanced oil recovery agents such as NaOH, NaHCO3 or Na2CO3 are not volatile, and thus do not reach steam chamber edges (even though they could in theory be carried to the bottom of the chamber by dissolving in residual hot water in the Injector Well).
Thermally unstable ammonium carboxylates useful for an in situ steam extraction method of removing heavy hydrocarbons from underground locations is disclosed in U.S. Ser. No. 62/053,446.
It is desirable to identify an in situ (that is, subterranean) method for recovering heavy hydrocarbons, such as bitumen from oil sands, that does not require injecting hydrocarbons into subterranean oil sands but that offers a greater recovery percentage than current CSS and SAGD processes.